Fortnightly - resource performancehttp://www.fortnightly.com/tags/resource-performance
enReliability by the Barrelhttp://www.fortnightly.com/fortnightly/2013/09/reliability-barrel
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>New England turns to fuel oil for the coming winter.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Bruce W. Radford</b> is publisher of <i>Public Utilities Fortnightly</i>. Contact him at <a href="mailto:radford@pur.com">radford@pur.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - September 2013</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>With cold weather now not far off, fear is rising in New England of a repeat of last winter, when natural gas delivery failures pushed the power system to the brink. To prevent a recurrence, the region’s grid operators are going back to the future: back to oil-fired generation, which dominated long before the emergence of a competitive wholesale power market.</p>
<p>To safeguard reliability for the coming winter heating season, ISO New England has called on the power industry, starting in December, to deliver an emergency inventory of up to 4.2 million barrels of fuel oil – a winter stockpile figured to be worth some 2.4 million MWh, assuming 42 gallons per barrel, 137,000 Btu per gallon, and a heat rate (thermal efficiency) for oil-fired power plants of 10,000 Btu/kWh.</p>
<p>That’s the total contribution from oil-fired generation that grid operators say they’ll need if temperatures this season should fall as low as in the winter of 2003 and ’04, the coldest seen in New England over the last 10 years.</p>
<p>Under this new “Winter Reliability Program,” oil-fired generators and dual-fuel units capable of fuel switching on five hours’ notice would offer to procure fuel oil and inject it into oil tanks across New England, to be available to generate power this coming winter should gas-fired generators encounter fuel delivery breakdowns as occurred last year. Those pipeline constraints drove intraday natural gas prices as high as $60/MMBtu, assuming that gas could be found at any price. (<i>See, this year’s April </i>Commision Watch<i> column, “</i><a href="http://www.fortnightly.com/fortnightly/2013/04/no-fuel-no-power"><span class="s1"><i>No Fuel, No Power</i></span></a><i>.”</i>)</p>
<p>The ISO has called for oil inventory supply bids stated in terms of the MWh-equivalent value of the oil. Winning bidders would earn two separate revenue streams. First, as a reward for capacity value, winners would be paid the amount of their bid – “as bid,” in ISO parlance. Second, they would remain free to offer their oil-fired generation into the ISO’s day-ahead energy market (DAEM) and earn the prevailing locational marginal energy price (LMP), but with no guarantee of clearing. The ISO wouldn’t directly compel dispatch of this newly found oil-fired capacity as a matter of course, but has set a target minimum oil dispatch rate of 4,000 MW per hour.</p>
<p>It’s important to note, however, that the lowest-priced inventory offers wouldn’t necessarily win out. Rather, the ISO would choose among oil supply bids based on at least a half-dozen factors – some seemingly a bit subjective – such as diversity of location, capability to replenish fuel tanks, and the historical availability and performance of the oil-fired generator, including the ability to respond to contingencies. In other words, the as-bid capacity payment would be awarded “out of market,” based upon ISO discretion and each supplier’s particular cost profile. There would be no uniform auction clearing price. The ISO decided against that – to the dismay of many critics – because of the many non-price factors involved in selecting the winning bids to supply the fuel oil inventory.</p>
<p>What’s more, the ISO would clear the oil bids manually. That’s because delivery of the initial tranche of fuel oil inventory would be required by the first of December, leaving too little time for the ISO to write or test new software for automatic bid evaluation and selection. And to get the ball rolling, the ISO opted to open the floor for bids even before the FERC had a chance to OK the program.</p>
<p>The ISO filed its plan with the Federal Energy Regulatory Commission (FERC) for approval on June 28. (<i>FERC Dkt. ER13-1851.</i>) As of the date of this writing, no FERC ruling had been issued. But already we’ve learned a few things.</p>
<p>As the first offers came in, the plan failed to live up to expectations. Bidders, it seemed, weren’t taking the bait.</p>
<p>The ISO announced in early August that its first solicitation had attracted fuel oil inventory bids worth only 1.4 million MWh, less than 60 percent of the total RFP quantity the ISO was seeking, but at a total bid price of approximately $60.66 million – a figure already much higher than the program’s initial estimated cost of $16 to $43 million. (<i>See, ISO Answer, FERC Dkt. ER13-1851, filed Aug. 6, 2013.</i>)</p>
<p>The problem, it seemed, was twofold. First, oil-fired generators saw the potential benefits as too uncertain, given the many non-price factors the ISO said it would consider in selecting the winning bids. Second, generators feared the potential downside, as the plan called for two different penalties (a per-barrel fine, plus denial of the as-bid capacity payment) for failing to meet inventory due dates, or replenish emptied tanks on time.</p>
<p>As the ISO conceded, “Participants indicated that these penalties were too harsh and that the ‘cliffs’ pursuant to which the entire amounts were lost or came due … approached too quickly.” So it proposed to relax the penalties and alter certain rules in a bid to save the program. (<i>See, Emergency Amendments to Pending Winter Reliability Program, FERC Dkt. ER13-1851, filed Aug. 9, 2013.</i>)</p>
<p>Overall, program critics have cited a host of problems. In particular, they note the lack of fuel neutrality that comes with an oil-only solution.</p>
<p> “There is no question that this is a discriminatory program,” said a group of PSEG companies that criticized the New England plan. (<i>Protest of PSEG Cos., p. 7, FERC Dkt. ER13-1851, filed July 19, 2013.</i>)</p>
<p>The Conservation Law Foundation pushed an alternative plan, designed with the assistance of gas industry expert Greg Lander, president of Skipping Stone LLC, to rely on expanded LNG imports to ensure winter reliability.</p>
<p>ISO New England in fact said it “would have preferred fuel neutrality,” but feared unintended impacts, given the “complexity of the gas supply chain and the significance of gas to the electric system.” By contrast, said the ISO, a fuel oil solution would come with “far fewer complications.”</p>
<p>For instance, while LNG imports might allow shippers to bypass choke points on the interstate pipeline system in delivering fuel to gas-fired generators, the ISO still saw possible “ripple effects” on prices and markets:</p>
<p>“If an ISO solution [such as one based on LNG] reduced the opportunity costs priced into the gas market … during a time of high gas demand,” the ISO wrote, “this would lower gas prices and send the wrong signal about the relative scarcity.”</p>
<p>Yet there remains the not-so-trivial matter that any oil-fired generation empowered by this new stockpile of 4 million-plus barrels likely won’t clear the region’s day-ahead energy market this winter unless power prices climb as high as $200/MWh or more. After all, that’s the marginal fuel operating cost implied by a 10,000 Btu heat rate and a likely fuel oil price of around $20/MMBtu.</p>
<p>The gas industry, in particular, has questioned why reliability must come at so high a price. Consider the comments filed at FERC on July 19 by two key gas pipelines serving New England, the Algonquin and the Maritimes and Northeast:</p>
<p>“Oil for power reserves in New England this winter is for consumers a costly option.</p>
<p>“ISO-NE here avoids threading the needle fully for the public… That ISO-NE elected an out-of-market option that would not result in a reduction in electricity prices should be perplexing to consumers in New England.”</p>
<h4>‘Stale’ Price Offers</h4>
<p>Here’s one way to think about the problem that has plagued New England.</p>
<p>When the region’s gas-fired generators see their promised fuel deliveries suddenly interrupted, such that natural gas becomes no longer available for power generation, such disruption undercuts basic assumptions built in to the region’s wholesale energy market. One such assumption is that fuel prices are less volatile than power prices over the short run.</p>
<p>Back at the turn of the current century, when the regional grids in the Northeast settled on a largely standard design for wholesale energy markets, with day-ahead bidding to determine which plants would come in at the lowest-cost and earn the right to run, no one likely envisioned that fuel prices would change much from day-ahead to real time. The market assumed that the plants deemed economic in the day-ahead auction would still be in merit by the start of the operating day.</p>
<p>Yet that’s no longer guaranteed in New England in winter.</p>
<p>With gas-fired generation now dominant, but competing against space-heating load, a cold snap can change the picture abruptly. A plant with the lowest marginal operating cost as of yesterday – a unit at the very top of the day-ahead bid stack – could fall out of merit today, within a matter of hours. That means that on the days when natural gas deliveries are most constrained, much of the fleet dispatched by the ISO could already have become uneconomic.</p>
<p>That New England now recognizes such a scenario as plausible can be seen from a new tariff the ISO has filed this summer, completely separate from its Winter Reliability Plan, that would give hourly flexibility to power plants bidding into the day-ahead energy market.</p>
<p>Under this proposal, known as the “offer flexibility changes,” generators bidding day-ahead would be permitted to recast their bids hour by hour, including price and quantity, during the interim between the close of day-ahead bidding and real time. They could alter their bids not only after the 10 a.m. bid closing and the 12:30 p.m. posting of cleared schedules, but also after the 2 p.m. close of the bid re-offer period, as is the case now, and then again after the expected 5 p.m. close of the ISO’s RAA process. That’s the process by which the ISO reviews the market results and ensures adequate resources will be available on the next day to meet the operating constraints of the system. And generators could alter their bids yet again every hour until real time, at the start of the operating day at 12 a.m., so that bids might continue to accurately reflect cost inputs and current conditions across the natural gas supply chain.</p>
<p>Anything less is unworkable when your end product can’t be stored and your fuel input is just-in-time.</p>
<p>In July the ISO filed testimony at FERC taken from Robert Ethier and Christopher Parent, the ISO’s v.p. and manager of market development, explaining why such measures are now required. This testimony features a hypothetical example that shows how electricity supply offers get “stale,” and markets out of whack, if gas-fired and oil-fired generation should trade places in the bid stack during the interim between the close of the traditional day-ahead bid re-offer period and the start of real time, such that the cheaper resources as of yesterday will have become the more expensive today.</p>
<p>As Ethier and Parent explain, such stale offers can leave some market participants less than willing to follow last-minute dispatch instructions from the ISO, as they would reflect the stale economics of 24 hours earlier. The example describes a hypothetical and sudden increase in the marginal operating cost for gas-fired power from $30 to $95/MWh during the interim between day-ahead and real time. Assuming a unit heat rate of 8,500 Btu/kWh, this cost jump would represent a gas price increase from about $3.50 to around $11/MMBtu – an event that was not all that unusual in New England last winter:</p>
<p>“Assuming that the gas-fired resource is the marginal resource, the energy component of the real-time LMP would be $30/MWh, based upon a forward expectation of the gas price, not the actual cost of gas in real time [$95/MWh], sending the wrong signal … and creating a disconnect between the marginal cost in electric markets and the marginal cost in the fuel markets… [I]n these circumstances the … gas-fired resource lacks a strong financial incentive … to follow dispatch instructions since each MWh of operation would result in a loss of $65/MWh.” <i>(Joint Testimony of Ethier &amp; Parent, p. 9, FERC Dkt. ER13-1877, filed July 1, 2013.)</i></p>
<p>Industry comments received on the ISO’s offer flexibility changes appear overwhelmingly supportive, at least on the basic idea of allowing hourly changes to day-ahead bid parameters. The few complaints voiced so far seem to deal only with the penalty that the ISO proposes – the so-called “lockout provision” – if generators who amend their bids by the hour fail to submit sufficient documentation of the new fuel cost that gives reason for the changed bid.</p>
<p>The New England Power Generators Association is one group that has questioned whether the ISO’s proposed lockout is too punitive.</p>
<p>As NEPGA notes, after a generator has submitted an hourly fuel price adjustment, it must provide the ISO’s Independent Market Monitor with a quote from a named supplier, or an invoice, or a price from a public trading platform. But if the generator’s amended supply offer differs too much from the fuel price reflected in the documentation submitted to the IMM, the generator is liable to be penalized: a two-month ban on submitting any hourly bid adjustments for the first offense, and a six month ban for a second offense committed within the year.</p>
<p>NEPGA claims these penalties are way too severe, considering that each hour represents a new opportunity for a gas-fired generator to recast its supply bid:</p>
<p>“Under the Offer Flexibility Changes, a market participant will have 25 opportunities per operating day to adjust its supply offer based on a change in fuel price; 24 for each of the hours of the operating day, and one [currently authorized] for the re-offer period.”</p>
<p>Thus, writes NEGPA, a two-month lockout would represent 1,500 lost opportunities for bid amendments; and a six-month lockout 4,500 lost bids. With such rights at risk, the generators say they would be forced to include a risk premium in their supply offers, reflecting gas market volatility over the course of a 24-hour day: an “inefficient market practice,” they say, that the OFC program is intended to correct. (<i>Comments of NEGPA, p. 7, FERC Dkt. ER13-1877, filed July 22, 2013.</i>)</p>
<p>“The sheer magnitude of the proposed penalty,” the group argues, “weighs against its approval.”</p>
<h4>Market Failures</h4>
<p>In a curious twist, the Maine Public Utilities Commission questioned why the ISO chose to base its calculation of need for oil inventory on the winter of 2003 and ’04, the coldest in 10 years, without weighing the probability of a recurrence of such temperatures. The PUC thus accused the ISO of abandoning traditional probabilistic analysis to assess reliability threats and resource adequacy, in favor of a more radical deterministic method.</p>
<p>Here the ISO’s response was both direct and revealing.</p>
<p>“Resource adequacy,” as the ISO noted, wasn’t the relevant consideration. “Rather, the motivating factor is … concern about resource performance<i>.”</i></p>
<p>As the ISO explained, its traditional resource adequacy analysis actually fails to capture any aspect of resource performance outside of annual forced outage rates and maintenance cycles:</p>
<p>“There are only very limited data about the probability of fuel shortages arising, and outages under these conditions tend to be highly correlated across resources – unlike traditional reliability modeling, where outages are assumed to be independent of one another.” (<i>Answer of ISO New England, p. 6, FERC Dkt. ER13-1851, filed Aug. 6, 2013.</i>)</p>
<p>“The primary driver of the winter reliability problems,” the ISO added, “is a lack of fuel, not broken machinery.”</p>
<p>Many other protests about the ISO’s winter reliability program also center on perceived market failures. The power generators association, for example, argues that over the past three years, the day-ahead market on average has cleared only 93 percent of next-day firm demand, and as little as 85 percent on some of the colder days this past winter. That shouldn’t happen, the theory goes, since day-ahead underbidding ordinarily should produce high-risk energy price volatility in real time, persuading load to participate more heavily in the DAEM.</p>
<p>But as energy marketer Hess Corp. explains, “that is not what is occurring in New England.”</p>
<p>Instead, as Hess alleges, ISO New England “is procuring a significant amount of resources out-of-merit after the day-ahead market closes,” such as through the reserve adequacy assessment (RAA) process. That’s how the ISO assures that next-day firm load needs are met, as well as contingency protection requirements. But as Hess notes, “such actions significantly increase out-of-market uplift costs … [such that] the true costs of supply are not reflected in real-time prices.” (<i>See Comments, p. 7, FERC dkt. ER13-1851, filed July 19, 2013.)</i></p>
<p>“In effect,” Hess argues, “real-time LMPs have been noticeably suppressed.”</p>
<p>Another energy marketer, GDF Suez, notes that analysis conducted by the ISO’s external market monitor found that on average for 2012, real-time energy prices for the hour ending at 7 p.m. were $7/MWh too low for a well-functioning energy market. </p>
<p>And with real-time prices lower, and volatility avoided, both load and supply have less reason to bid day ahead, and become more willing to bet in real time. That only exacerbates New England’s winter reliability problems, as NEPGA points out:</p>
<p>“Much of the complication of gas-electric coordination arises from deferring scheduling of gas-fired generation to last minute dispatch situations.”</p>
<h4>Firm Around the Clock</h4>
<p>In the April column we noted how INGAA president and CEO Don Santa, representing the interstate pipeline sector, had faulted regional power markets for failing to take fuel supply surety into account in clearing supply offers from generators, and how ISO New England chief Gordon van Welie had told this reporter that it wasn’t feasible to try rewarding generators in the day-ahead market for having purchased firm pipeline capacity.</p>
<p>But perhaps we haven’t yet heard the last word on this issue.</p>
<p>First, consider that back in November of 2012, the ISO sent a memo to the NEPOOL Markets Committee offering a new interpretation of ISO tariffs. As the memo explained, any generator that takes on a capacity obligation in the ISO’s Forward Capacity Market must offer supply in the day-ahead and real-time markets, and so must arrange for fuel supplies to support any dispatch up to the unit’s economic maximum operating level if called on to run by the ISO – even if the plant hasn’t cleared the DA or RT auctions – since lack of fuel owing to a failure to make adequate supply arrangements can’t qualify as a “forced outage” or “physical cause” of unit unavailability.</p>
<p>That memo in turn led NEPGA, the generator association, to lodge a complaint at FERC, asserting that this new tariff interpretation, as a practical matter, would require generators to have fuel supplies available “around the clock.” (<i>See, NEPGA v. ISO New England, FERC Dkt. EL13-66, filed May 17, 2013.</i>)</p>
<p>As NEPGA puts it, such a mandate would be grossly inefficient and impossible to achieve (given current pipeline constraints), and moreover, would contradict “decades of established industry practice.” The complaint remained unresolved at press time.</p>
<p>And even more intriguing, however, is the joint testimony submitted in July in support of the winter reliability program for expanded oil stockpiles, in which the ISO’s Robert Ethier and Peter Brandien, who serves as system operations v.p., said the ISO was considering changes to its wholesale market structure “to strengthen the incentives for all generators to make adequate fuel arrangements.” (<i>Joint Testimony, FERC Dkt. ER13-1851, filed June 28, 2013.</i>)</p>
<p>Ethier and Brandien elaborated further:</p>
<p>“These market rule changes will cause generators to include the costs of responding to these incentives in their offers, likely causing an increase in wholesale electricity prices, which over time will result in additional fuel infrastructure.”</p>
<p>Wishful thinking? The pipelines seem to think so.</p>
<p>As was noted by Spectra’s Algonquin and Maritimes &amp; Northeast pipes, “Spectra Energy’s Algonquin Incremental Market Expansion Project [known as AIM] has been proposed for quite some time for the region, and Spectra has been actively pursuing both traditional LDC and electric industry support for well over two years. Yet not a single merchant power plant currently is supporting AIM by committing to capacity in the form of executed precedent agreements for the project.” (<i>Comments, p. 5, FERC Dkt. ER13-1851, filed July 19, 2013.</i>)</p>
<p>TransCanada Power Marketing was more blunt, suggesting in comments filed in July that merchant generators would never spring for long-term firm gas transporation:</p>
<p>“Notwithstanding ISO-NE’s assertion … no changes it could suggest plausibly would provide an economic rationale that would support … 10, 20- or 30-year commitments, or even commitments of a year or two to pay for firm transportation … because such an obligation would be one-sided.</p>
<p>“Merchant generators would guarantee to pay for the cost … but load would not make a parallel commitment to purchase electric energy at prices that include those costs.”</p>
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<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/new-england">New England</a><span class="pur_comma">, </span><a href="/tags/natural-gas">Natural gas</a><span class="pur_comma">, </span><a href="/tags/oil-fired">oil-fired</a><span class="pur_comma">, </span><a href="/tags/iso-new-england">ISO New England</a><span class="pur_comma">, </span><a href="/tags/stockpile">stockpile</a><span class="pur_comma">, </span><a href="/tags/winter-reliability-proram">Winter Reliability Proram</a><span class="pur_comma">, </span><a href="/tags/fuel-switching">fuel switching</a><span class="pur_comma">, </span><a href="/tags/day-ahead-energy-market">day-ahead energy market</a><span class="pur_comma">, </span><a href="/tags/daem">DAEM</a><span class="pur_comma">, </span><a href="/tags/locatinal-marginal">locatinal marginal</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/non-price-factors">non-price factors</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/pseg-0">PSEG</a><span class="pur_comma">, </span><a href="/tags/conservation-law-foundation">conservation Law Foundation</a><span class="pur_comma">, </span><a href="/tags/greg-lander">Greg Lander</a><span class="pur_comma">, </span><a href="/tags/skipping-stone">Skipping Stone</a><span class="pur_comma">, </span><a href="/tags/iso-ne">ISO-NE</a><span class="pur_comma">, </span><a href="/tags/robert-ethier">Robert Ethier</a><span class="pur_comma">, </span><a href="/tags/christopher-parent">Christopher Parent</a><span class="pur_comma">, </span><a href="/tags/offer-flexibility">offer flexibility</a><span class="pur_comma">, </span><a href="/tags/new-england-power-generations-association-nepga">New England Power Generations Association NEPGA</a><span class="pur_comma">, </span><a href="/tags/maine-public-utilities-commission">Maine Public Utilities Commission</a><span class="pur_comma">, </span><a href="/tags/resource-adequacy">resource adequacy</a><span class="pur_comma">, </span><a href="/tags/resource-performance">resource performance</a><span class="pur_comma">, </span><a href="/tags/hess">Hess</a><span class="pur_comma">, </span><a href="/tags/reserve-adequacy-assessment">reserve adequacy assessment</a><span class="pur_comma">, </span><a href="/tags/raa">RAA</a><span class="pur_comma">, </span><a href="/tags/gdf-suez">GDF SUEZ</a><span class="pur_comma">, </span><a href="/tags/ingaa">INGAA</a><span class="pur_comma">, </span><a href="/tags/don-santa">Don Santa</a><span class="pur_comma">, </span><a href="/tags/gordon-van-welie">Gordon van Welie</a><span class="pur_comma">, </span><a href="/tags/nepool">NEPOOL</a><span class="pur_comma">, </span><a href="/tags/peter-brandien">Peter Brandien</a><span class="pur_comma">, </span><a href="/tags/spectra">Spectra</a><span class="pur_comma">, </span><a href="/tags/transcanada-power-marketing">TransCanada Power Marketing</a><span class="pur_comma">, </span><a href="/tags/algonquin">Algonquin</a><span class="pur_comma">, </span><a href="/tags/maritimes">Maritimes</a> </div>
</div>
Sun, 01 Sep 2013 20:19:49 +0000meacott16750 at http://www.fortnightly.com